The present invention relates to fluids useful for treating injection wells to prevent or to reduce migration of particulates therein.
Generally, in the recovery of hydrocarbons, such as oil, from a subterranean formation, the energy required to force the hydrocarbons into producing wells may be supplied by the natural pressure drive existing in the formation or by mechanically lifting hydrocarbons from the subterranean formation through the wells bores of producing wells to the surface. However, at the end of primary recovery operations, the natural driving pressure may be below a pressure sufficient for production while still leaving a substantial quantity of hydrocarbons in the subterranean formation. In such cases, secondary recovery methods, such as injection operations, may be used to retrieve the remaining hydrocarbons. For example, in typical injection operations the energy for producing the remaining hydrocarbons from the subterranean formation may be supplied by the injection of fluids into the formation under pressure through one or more injection wells penetrating the reservoir. The injection fluids then drive the hydrocarbons toward one or more producing wells that are in the reservoir. Typical injection fluids include water, steam, carbon dioxide, and natural gas.
The sweep efficiency of injection operations, however, may vary greatly depending on a number of factors, such as variability in the permeability of the formation. As used herein the term “sweep efficiency” refers to the measure of the effectiveness of an injection operation wherein the operation depends on the volume of the reservoir contacted by the injected fluid. That is, sweep efficiency measures the percentage of the hydrocarbons displaced from the reservoir by the injection fluid. In particular, where the subterranean formation contains high permeability zones, the injection fluids may flow through the areas of least resistance, e.g., through the high permeability zones, thereby bypassing less permeable zones. While injection operations may provide the energy necessary to produce hydrocarbons from the high permeability zones, hydrocarbons contained within less permeable zones may not be driven to the one or more production wells penetrating the formation.
However, injection wells experience problems of varying degrees of severity when formation solids migrate or are weakened due to the injection process. These problems are more likely and may be more acute in injection wells that penetrate weak or unconsolidated formations, and/or injection wells that are subject to frequent shut down and start up cycles.
For example, the injection of fluids into a reservoir tends to weaken the near well bore region surrounding the injection well. The injection fluids may reduce the cohesive strength of the rock surrounding the well bore. This effect may be especially severe when the injection fluid is introduced to the injection well at pressures that exceed the fracture pressure of the formation around the injection well bore. This weakening may be particularly severe when a formation is subjected to rapid shut down cycles, such cycles may cause a water hammer effect that creates localized stresses and leads to reduced consolidation. Injection wells that receive a particularly large amount of injection fluid, for example over 30,000 barrels of injection fluid per day are particularly susceptible to loss of consolidation of formation particulates.
In addition, non-uniform injection rates can cause differential pressure to build between reservoir layers. This differential pressure becomes particularly problematic if the well is ever shut in for any reason. Upon shut in, the pressure between the layers attempts to equalize, which causes cross-flow between the layers and may result in the influx of formation particulates into the well bore (causing unwanted solids production) or into the interstitial spaces within the formation (decreasing permeability). This effect may be particularly pronounced in areas of the formation that have already been weakened by the injection fluid.
Another possible failure mechanism for an injection well is that rapid shut down cycles for an injection well can result in water hammer effects that create high localized stress in the immediate well bore region. These local stresses can result in mechanical failure and production of formation solids. Further, in weak formations, injecting water into the formation can desegregate the rock in the near well bore region and increase the pressure around the well bore, weakening grain-to-grain bonds, and, in some cases forming a completely unconsolidated mass.
While conventional cased and perforated wells have been used for water injection wells, but have been highly prone to failure. Screen only, including expandable screen, completions open hole gravel pack, cased hole gravel pack and frac and pack completions have been used with varying degrees of success, but failure rates are unacceptable.
Moreover, in some cases there have been channeling problems whereby fluid from the injection wells follows either high permeability sections or channels along bedding plains to the production wells. In these cases, even a small amount of sand produced at the injection well or the production well can result in a fully connected channel forming between the injection well and the production well. This creates an undesirable situation wherein the injected fluid, rather than propelling hydrocarbons for production, is simply produced out of the producing well. Stabilization of the formation particles in these high permeability sections will help stop the movement and erosion of sand into the production well and help minimize the creation of these high capacity channels.